Vincent Sorgi
President and Chief Executive Officer at PPL
Thank you, Andy, and good morning, everyone. Welcome to our third quarter investor update. Let's start with our financial results and a few highlights from our third quarter performance on Slide 4. Today, we reported third quarter GAAP earnings of $0.29 per share. Adjusting for special items, third quarter earnings from ongoing operations were $0.42 per share. Given the strength of our year-to-date performance, we narrowed our 2024 ongoing earnings forecast to $1.67 to $1.73 per share from the prior forecast range of $1.63 to $1.75 per share. As a result, we've increased the midpoint $0.01 to $1.70 per share.
Throughout the third quarter, we continued to make excellent progress on delivering our 2024 priorities. We're on track to complete approximately $3.1 billion in infrastructure improvements this year to advance a reliable, resilient, affordable and cleaner energy future for our customers. And through our ongoing business transformation initiatives, we're on pace to achieve our annual O&M savings target of $120 million to $130 million this year compared to our 2021 baseline O&M. Looking ahead, we're well-positioned to achieve our projected 6% to 8% annual earnings per share and dividend growth through at least 2027.
We're focused on executing our capital plan, which includes $14.3 billion in infrastructure improvements from 2024 to 2027 with continued potential upside driven by data center connections in Pennsylvania and Kentucky, new generation in Kentucky, new enterprise-wide technology investments and additional resiliency investments across all of our jurisdictions as we combat more frequent and severe storms. And across PPL, we continue to drive efficiencies through our Utility of the Future strategy keeping us on pace to achieve our annual O&M savings target of at least $175 million by 2026, which again is compared to our 2021 baseline.
Moving to Slide 5. On October 18, LG&E and KU submitted their updated Integrated Resource Plan or IRP to the Kentucky Public Service Commission. The IRP provides a robust analysis of a wide range of variables, including demand growth, fuel prices, supply side resource costs and pending environmental regulations, all to guide our resource planning. This year's IRP examined 300 potential resource portfolio and fuel price combinations to arrive at a plan to most effectively meet forecasted demand over the next 15 years. It's important to note that the IRP is submitted for informational purposes only.
That said, the detailed analysis provides reasonable insights about future generation needs and helps us to identify no regrets recommendations given there is uncertainty with some of the inputs. Key drivers in our latest IRP analysis include stronger demand forecasts and higher costs for new supply side resources from what we saw in our last IRP, which was filed three years ago in 2021. In terms of demand, our mid load scenario reflects load growth of nearly 1.5% annually through 2039, but more importantly projects annual load growth of over 3% through 2032, which is significantly impacted by projected data center load.
We evaluated several scenarios for data centers ranging from zero to nearly 2 gigawatts of new load by 2032 with the mid-load scenario assuming just over 1 gigawatt. Based on the interest levels that LG&E and KU have already seen from developers, we view no or low data center growth as unlikely. Regarding the cost of new generation, we've seen those costs increase markedly since our 2021 IRP, except for batteries. That increases the relative value of our existing generation resources and significantly impacted the generation mix recommended in this year's IRP.
Regarding the battery costs, this is the first time in our ongoing resource planning that the sum of capital and non-fuel O&M costs for battery storage with tax incentives included is less than the cost of new simple cycle combustion turbines. For this reason, our recommended plan includes the addition of 900 megawatts of battery storage. Importantly, due to the price increases in solar generation, we are not assuming the 637 megawatts of solar PPAs that were approved by the KPSC in our 2022 CPCN get built. As noted in our IRP, the impact of environmental regulations remains a key uncertainty as three major regulations are the subject of current federal court challenges.
Our IRP modeled four different environmental regulation scenarios ranging from none to all of the regulations becoming enforceable. The updated IRP assumes all resources and retirements approved in our last CPCN proceeding are completed as planned by 2028, except for the solar PPAs that I just mentioned. This includes our approved plans to retire 600 megawatts of aging coal and 50 megawatts of aging peaking units by 2027. In addition, it includes building a new 640 megawatt natural gas combined cycle unit, 240 megawatts of company owned solar and 125 megawatts of battery storage.
Above and beyond this generation, the IRP lays out several resource plans including two we've referenced on this slide, a recommended resource plan as well as an enhanced solar plant applicable in certain scenarios. The recommended plan reflects our no regrets approach to planning much like our latest CPCN filing. That includes important generation development even if scenarios that reflect high economic load growth or CO2 regulations do not come to fruition. This plant projects the need to build an additional 2,700 megawatts of new generation from 2028 through 2035 to safely, reliably and affordably serve future demand growth.
This includes two new 650 megawatt combined cycle natural gas plants, one in 2030 and another one in 2031. It includes the addition of 400 megawatts of new battery storage in 2028 and 500 megawatts of additional battery storage in 2035. It also includes 500 megawatts of solar in 2035. The recommended plan also projects the need to add new environmental controls at the Gen and Trimble County coal plants to ensure compliance with ELG and NOx regulations. The enhanced solar plan meanwhile, differs from the recommended plan only in the timing and level of new solar generation added. Rather than adding 500 megawatts of solar in 2035, the enhanced solar plant would accelerate and boost solar additions to 1,000 megawatts by 2032 to address potential data center interest in carbon-free generation or a faster than projected decline in solar prices.
Based on our analysis of current factors, we see potential additional generation needs ranging from 2,700 to 3,200 megawatts with associated capital investments, including the environmental retrofits for the coal plants of $6 billion to $7 billion to 2035 using current pricing estimates. We also evaluated the prospects of joining an RTO in our review of options, which concluded that we would be introducing significant unquantifiable risk to our customers, which is not surprising based on what we are seeing in other RTOs. Our next steps in the IRP process are to engage with the KPSC over the next few months and discuss the various plans we've provided. We would expect to file an additional CPCN request as early as the first quarter of next year to address near-term generation needs for our customers.
Moving to Slide 6 and an update on data center development. Our Pennsylvania and Kentucky service territories continue to attract growing interest from data center developers. In our Pennsylvania service territory, we now have over 39 gigawatts in our queue with 8 gigawatts in advanced stages of planning, up from the 5 gigawatts we highlighted during our second quarter call in August. We estimate these 8 gigawatts represent incremental PPL capital needs of $600 million to $700 million in the 2025 to 2029 time frame, none of which are reflected in our current capital plan. Note that we've included these types of projects in our latest PJM large load forecast, which shows that PPL Electric has the second highest projected peak load additions in PJM through the end of this decade.
It's important to note that projects in the queue may include duplicates due to developers assessing multiple sites for the same project and it's important to highlight that all the projects in our queues are in front of the meter projects. Projects in the advanced planning stages have signed agreements. They are in various stages of PJM's review process with some having completed those reviews. Costs incurred by PPL for these projects are reimbursable by developers even if they do not move forward with the projects. Recall that each new data center connection will lower transmission costs for customers. The savings are expected to occur as the data center load ramps-up over the next several years and the data centers begin to pay transmission charges.
In terms of the amount, we estimate that for the first gigawatt of data center demand that's connected to the grid, our residential customers could save nearly 10% on the transmission portion of their bill assuming a PPL investment level of about $100 million which for the average residential customer and based on current rates would represent about $3 per month in savings. While additional data center connections will also lower transmission costs for customers, the amount of those savings will depend on a number of factors, including timing of load ramp, the amount of investments required and the peak load on our system.
Turning to Kentucky. We have about 400 megawatts in advanced stages of planning with potential to increase up to 1 gig. Active data center requests in Kentucky now total nearly 3 gigawatts of potential demand, an increase from 2 gigawatts at the time of our second quarter call. As in Pennsylvania, any transmission upgrades in Kentucky would be additive to our capital plan, although the more significant capital investments in Kentucky would arise from any incremental generation investments. As I shared earlier, the recommended plan in our IRP projects a need for additional natural gas and battery storage beyond what was in our CPCN approved last year to support longer-term economic development and data center load growth.
Moving to Slide 7 and several key operational and regulatory updates. LG&E and KU responded well to the remnants of Hurricane Helene, which knocked out power to more than 224,000 customers and resulted in 1,600 downed wires and 160 broken poles. This storm was the fourth most significant weather event for the region in the last 20 years. We restored 95% of our customers within four days and all customers capable of receiving service within six days. In a great example of our One PPL strategy, crews from our Pennsylvania operations and more than 400 contract resources aided in the effort. We've since requested regulatory asset treatment for about $11 million in operating expenses tied to our restoration efforts.
Once our restoration efforts in Kentucky were complete, we were proud to send over 400 employees and contractors from our utilities in Pennsylvania, Rhode Island and Kentucky to support our colleagues in Florida, Georgia and Virginia following the significant damage sustained by Hurricanes Helene and Milton. Mutual assistance is one of those areas that makes our industry truly unique and I thank all the men and women on our teams that provided that much needed support. I also thank all the men and women from Comed, Duquesne Light, NIPSCO and CenterPoint that helped us in our efforts to restore power to our Kentucky customers during Hurricane Helene.
And other updates from Kentucky, in October, we filed a request with the KPSC to recover $125 million in retirement costs associated with Mill Creek One, which is set to retire by the end of this year. We requested approval to recover the costs through the Retired Asset Recovery rider or RAR in our first filing under this new mechanism. The rider provides cost recovery over a 10 year period upon retirement of such assets as well as a return on those investments at the utilities then weighted-average cost of capital. The implementation of the RAR rider if approved will result in a slight bill credit for customers beginning in May 2025 based on the current procedural schedule established by the commission.
Turning to Pennsylvania. Our disc waiver petition to increase the disk revenue cap from 5% to 9% continues to proceed through the process as expected. We've completed the briefing process and anticipate a recommended decision in November from the ALJ that's assigned to the case with a PUC decision to follow in early 2025. Also in Pennsylvania, PPL Electric Utilities yesterday announced new price to compare rates effective December 1. The new residential price to compare represents about a 2% decrease compared to last year's winter price to compare price. In all aspects of our business, our companies remain very focused on affordability for our customers. This focus also extends to how we purchase power for non-shopping customers in PA.
With this in mind, we were pleased to reach a settlement with the parties to our latest default service program and procurement plan filed with the PUC. We are seeking approval of our plan to procure electricity from June 1, 2025 through, 31, 2029 to meet PPI Electric's provider of last resort obligations. Our latest plan which we filed in March includes modifications to the current product mix and auction timing that PPL Electric uses to buy power. These modifications are intended to strengthen price stability and lower prices for customers, while supporting resource adequacy and fostering the continued growth of renewable generation. We expect a PUC decision on the settlement by the end of the year.
Shifting to Rhode Island, I am pleased to report that we completed the integration of Rhode Island Energy into PPL in the third quarter exiting the transition services entered into with National Grid when we acquired Rhode Island Energy in May 2022. I can't say enough about how well our teams rallied as one PPL to deliver this outcome, which involved exiting more than 130 transition services in phases over the past two years. It was truly a team effort from Rhode Island to Pennsylvania to Kentucky as well as everyone at National Grid that worked so hard to make the transition possible. We're excited to have Rhode Island Energy now fully integrated to best serve our customers.
Finally, in September, the Rhode Island Public Utilities Commission approved the company's winter last resort service rates as filed. The rate for non-shopping residential customers effective October 1 reflects an 8% decrease from last year's winter rate and we're pleased to be able to pass those savings on to our customers.
I'll now turn the call over to Joe for the financial update.
